Argillaceous formations account for about 75% of drilled sections in oil, gas and geothermal subterranean wells and cause approximately 90% of wellbore instability-related problems during the drilling operations. The formations, including shales, mudstones, siltstones and claystones, are of a fine-grained nature and low permeability but yet are fairly porous and normally saturated with formation water. The combination of these characteristics results in the formations being highly susceptible to time-dependent effective mud support change, which is a function of the difference between the mud (wellbore) pressure and pore fluid (formation) pressure.
When drilling under an overbalanced condition in argillaceous formations without an effective flow barrier present at the wellbore wall, mud pressure will penetrate progressively into the formation. Without an isolation (impermeable) membrane on the wall, an effective barrier will not be formed due to the low permeability of the formation. The low filtration rate will result in negligible deposition of drilling mud solids on the wellbore wall and any solid deposition will be eroded by the hydrodynamics of the drilling mud. Due to the saturation and low permeability of the formation, penetration of a small volume of mud filtrate into the formation results in a considerable increase in pore pressure near the wellbore wall. The increase in pore pressure reduces the effective mud support, which leads to a less stable wellbore condition.
The fine pores and negative clay charges on pore surfaces make argillaceous formations exhibit membrane behavior. Hence the flow of water out of (or into) such materials due to the chemical potential mechanism is somewhat similar to the flow of water through a semi-permeable membrane. The driving force involved in the water transportation (for zero overbalance conditions) is the chemical potential gradient across the membrane, which is generally related to the difference in solute (salt) concentration i.e., water activity. With the water activity of the drilling mud being lower than the formation activity, an osmotic outflow of pore fluid from the formation will reduce the pore pressure in the formation. If the osmotic outflow is greater than the inflow due to the hydraulic gradient (mud pressure penetration), there will be a net flow of water out of the formation into the wellbore. This will result in lowering of the pore pressure below the in-situ value and dehydration of the formation. The associated increase in the effective mud support and formation strength will lead to an improvement in the stability of the wellbore. For an ideal semi-permeable membrane, all solutes are reflected by the membrane and only water molecules can pass through the membrane. However, argillaceous materials exhibit a non-ideal semi-permeable (‘leaky’) membrane behavior to water-based solutions because they have a range of pore sizes including wide pore throats, which result in significant permeability to solutes. The wide throats reduce the solute interaction with the pore surfaces, which increase the permeability of the membrane to solutes. The solutes transferred across the membrane system will reduce the chemical potential (water activity) of the pore fluid. This will gradually reduce the chemical potential difference between the drilling mud and the formation, and consequently result in a reduction in the effective mud support.
Two parameters that can be manipulated to increase the osmotic outflow of pore fluid are salt type and concentration, and by membrane efficiency. The membrane efficiency is a measure of the capacity of the membrane to sustain osmotic pressure between the drilling mud and argillaceous formation. The osmotic outflow increases, with increase in salt concentration and membrane efficiency. The membrane efficiency generated by water-based drilling mud can be increased by partially plugging the pores with mud additives, which will restrict the movement of salts between the drilling mud and the formation.
It is worth noting that oil-based and synthetic-based drilling muds generate a highly efficient membrane through their water-in-oil emulsion, i.e., independently of the formation. As a result, the stability of wells drilled in argillaceous formations with oil-based and synthetic-based drilling muds can be greatly enhanced. However, incorrect salinity within the water phase of the drilling mud may still result in time-dependent wellbore instability in argillaceous formations.
Hence, there is a need for a field-based pragmatic method and computer program product for calculating drilling mud salinity and selecting salt type for water-based, synthetic-based and oil-based drilling muds to either prevent or minimize pore pressure increase near the wellbore wall inside argillaceous formations during overbalanced drilling, which could otherwise lead to time-dependent wellbore instability in the formations through which a borehole has been drilled.